Many combustion processes produce flue gas emissions contaminated with carbon dioxide that contribute to global warming and environmental damage. Gas-fired power plants are an important source of such flue gases, and their emissions are particularly challenging to treat because the volume of flue gas generated is very large and the carbon dioxide concentration, is low.
In conventional power generation processes, a gaseous fuel (such as natural gas or syngas) is combusted in the presence of oxygen, producing a stream of hot, high-pressure gas. This hot, high-pressure gas is then used to drive one or more gas turbines, which in turn drive a generator, producing electrical energy. The exhaust gas from the turbines is still very hot and may contain as much as 50% of the energy generated by the combustion process. In the past, this remaining heat may simply have been dissipated in the form of hot exhaust gas.
A process flow diagram for a more modern conventional gas-fired power plant is shown in FIG. 6. An incoming air stream, 602, is compressed from atmospheric pressure to 20-30 bar, for example, in an air compressor unit, 609. The compressed gas, stream 603, is combusted with the incoming fuel gas, stream 601 (typically, but not necessarily, natural gas) in combustor, 604. The hot, high-pressure gas from the combustor, stream 607, is then expanded through the gas turbine section, 606. The gas turbine is mechanically linked to the air compressor, 609, and an electricity generator, 611. The low-pressure exhaust gas, stream 605, from the gas turbines is still hot. Optionally, some heat content from this gas can be recovered in a steam boiler, 612, which, in a combined cycle operation, explained below, is used to make additional electricity in a steam turbine.
A major plant design issue is the temperature of the gas entering the turbines. The temperature of the combusted gases can be in excess of 2,000° C. or 3,000° C., hot enough to melt the turbine blades if the gas were passed directly to the turbine. In most plants, therefore, the compressor train is designed to compress two or three times the volume of incoming air that is needed for the combustion step on a straight stoichiometric basis. The excess air passes through the combustor without reacting and acts as a diluent, thereby cooling combustor exhaust stream, 607, to a temperature at which it can safely be fed to the turbine. In the alternative, all or some of the excess air may bypass the combustor entirely, and may be used to dilute and cool the exhaust upstream of the turbine or within the turbine itself, as indicated by dashed line 610.
When excess air is used to dilute the combustion products, the exhaust gas stream, 613, from the turbine is correspondingly dilute in carbon dioxide, and may contain only 3-5% carbon dioxide. Recovery of carbon dioxide from this dilute, low-pressure, yet very high-volume gas stream is, difficult and very expensive. In recent years, modified designs in which a portion, 608, of the turbine exhaust gas is returned as cooling/diluent gas have been used. Using part of the exhaust gas in this way increases the carbon dioxide concentration in the final exhaust gas and reduces the volume of gas that must be treated if carbon dioxide recovery is to be attempted.
The amount of exhaust gas that can be recycled is limited by the oxygen content of the gas mixture 603 delivered to the combustion chamber. When excess fresh air is used as the diluent, this gas mixture contains about 21% oxygen; when exhaust gas is recycled, the oxygen content drops in proportion to the amount of exhaust gas in the mix. If the oxygen content drops below about 15%, however, changes to the turbine or combustor design may be required.
In recent years, there has been considerable interest in combined cycle power generation to improve energy efficiency in gas-fired power plants. A combined cycle power plant generates additional electricity by using the hot exhaust gas from a gas turbine in an HRSG (heat recovery steam generator) to boil water to make steam. The steam, in turn, is used to drive a steam turbine, generating additional electricity.
A combined cycle plant may use methane, from natural gas or other source, as fuel. In countries where coal, other hydrocarbon fuels or biomass are available, such feedstocks can be gasified to provide syngas to use as fuel for the plant. Steam created by cooling the raw syngas may be used in the steam turbine. Such processes are referred to as IGCC (integrated gasification combined cycle) processes. Combined cycle power generation processes of various types are well-known in the art and are described, for example, by Rolf Kehlhofer et al. in Combined-Cycle Cas & Steam. Power Plants (3.sup.rd ed., PennWell Corporation; Tulsa, Okla., 2009).
Combined cycle power generation is inherently more expensive than using a gas-turbine-only process, because additional equipment is required. However, over time, the value of the additional energy generated should offset the initially higher capital cost. As a result, most new gas power plants being built in North America and Europe are combined cycle.
Gas separation by means of membranes is a well-established technology. In an industrial setting, a total pressure difference is usually applied between the feed and permeate sides, typically by compressing the feed stream or maintaining the permeate side of the membrane under partial vacuum. This pressure difference provides a driving force for transmembrane permeation.
Although pressure-driven processes are the norm, it is known that a driving force for transmembrane permeation may be supplied by passing a sweep gas across the permeate side of the membranes, thereby lowering the partial pressure of a desired permeant on that side to a level below its partial pressure on the feed side. In this case, the total pressure on both sides of the membrane may be the same, the total pressure on the permeate side may be higher than on the feed side, or there may be additional driving force provided by keeping the total feed pressure higher than the total permeate pressure.
The use of a process including a membrane separation step operated in sweep mode for treating flue gas to remove carbon dioxide is taught in co-owned U.S. Pat. Nos. 7,964,020; 8,025,715; 8,246,718; 8,177,885; 8,220,247; 8,016.923; 8,034,168; and 8,220,248, as well as in co-owned and copending application Ser. No. 13/123,364, filed Apr. 8, 2011; Ser. No. 13/548,827, filed Jul. 13, 2012; and Ser. No. 13/665,620, filed Oct. 31, 2012.
Despite the improvements offered by the inventions described in the above patents and pending applications, there remains a need for better treatment techniques, especially techniques that can be integrated into gas-fired power plants, such as combined cycle and IGCC plants.